Page 1374 – RTO Insider

December 13, 2016

Mass. Considering Storage Mandate

By William Opalka

BOSTON — Massachusetts officials will announce by the end of the month whether to join California in mandating the procurement of energy storage.

For the more than 300 people who attended or live-streamed Raab Associates’ 152nd New England Electricity Restructuring Roundtable last week, however, the only question is how much storage the state is likely to order. The session provided a briefing on both the policies driving the adoption of storage and the companies that are deploying the technologies.

Judith Judson, commissioner of the Massachusetts Department of Energy Resources, said the “State of Charge” study produced a surprising result: Up to 1,766 MW of advanced storage could save ratepayers $2.3 billion. Comments on whether Massachusetts should set targets are due Friday.

“We have reduced average consumption in Massachusetts, but our peak demand continues to grow,” she said. “Our top 1% of the hours accounts for 8% of our electric spend. Our top 10% of hours account for 40% of our electric spend. … So [storage] could be a tremendous savings for ratepayers.”

massachusetts energy storage mandate — | *RTO Insider*

California Leads the Way

California has led the nation in mandating storage, with 1.3 GW to be deployed by 2024. Since 2013, 630 MW in projects have been approved, California Public Utilities Commissioner Carla Peterman said.

“The commission has to determine that these projects are viable and cost-effective. Typically, that requirement has not been placed on emerging technologies. For example, there is not a similar requirement on our solar incentives,” said Peterman, who participated via video.

Jesse Jenkins, of the Massachusetts Institute of Technology Energy Initiative’s Utility of the Future study, said the two-year effort that will be released this week includes an examination of the impact of distributed storage resources.

Locational Value

Jenkins said storage and demand response resources in some locations can have a value three to 10 times greater than a typical distribution node. “They can deliver [cost benefits] to the power system, but only if the incentives are appropriately granular,” Jenkins said.

Roger Lin, senior director of product marketing for NEC Energy Solutions, described the company’s 2-MW, 3.9-MWh battery storage system in Sterling, Mass., which it says will be the first utility-scale project in the state and the largest battery-based system in New England.

The project will provide the town’s municipal utility with a backup during weather-related power outages and a way to save money by shaving its peak usage. He said storage could have saved the town several hundred thousand dollars over a couple hours when the town’s 3-MW solar array became shrouded by clouds at 2 p.m. on a September day and LMPs jumped from less than $100/MWh to more than $500.

“That cloud cover came at the worst possible time, at the system peak, as the pro rata share of transmission charges and forward capacity market charges” is determined, he said.

Demand Reduction

Vic Shao, CEO of Green Charge Networks, said his company focuses on the software and controls that predict when peaks will come.

“In California, we really focus on demand reduction. California is particularly expensive, with demand charges going up by about 10% a year,” he said.

“When it comes to storage, controls are everything,” said Josh Castonguay, chief innovation executive at Green Mountain Power in Vermont, which has added storage to a 2.5-MW solar array on a capped landfill. “Because at the end on the day, that’s what’s going to unlock all the value streams for you.”

Matthew Morrissey, vice president of Deepwater Wind’s operations in Massachusetts, said the company, which built the first offshore wind plant in the U.S. in Rhode Island, is developing storage capabilities so it can bid into capacity auctions and state solicitations. He said the company recently won a solicitation to provide the Long Island Power Authority offshore wind combined with storage — beating out more traditional gas-fired alternatives on price.

“Even with offshore wind, where we have wonderful peak incidences where demand matches our power curve perfectly, we recognize we must have an offset of storage,” he said.

Fouad Dagher, director of new energy solutions at National Grid, also emphasized the need to install storage where it provides the most benefit. “How do we dispatch it? When do we dispatch it? And that’s very important for capturing the value,” he said. “Where is the best location to place something?”

December 13, 2016

FERC OKs Changes to ISO-NE Dispatch Rules

By Rich Heidorn Jr.

FERC last week approved ISO-NE rule changes requiring almost 1,100 MW of non-dispatchable generation to purchase equipment allowing them to receive electronic dispatch instructions from the RTO (ER17-68).

FERC OKs Changes to ISO-NE Dispatch Rules — Utility scale biomass plants in New England | *Innovative Natural Resource Solutions*

The new rules, proposed by ISO-NE and the New England Power Pool in October, apply the dispatchability requirements mostly to municipal solid waste (406 MW) and biomass (263 MW) facilities. Also included are 175 MW of non-intermittent hydro generation and 157 MW of resources that exceed the below-5-MW limitation for settlement-only resources.

They will be required to order remote terminal units — and communication circuits to connect them to the ISO-NE network — by Jan. 15, and to become dispatchable within 12 months afterward. The rules, which will be phased in through June 2020, also require intermittent resources participating in the Forward Capacity Market to offer into the day-ahead energy market.

ISO-NE said the changes will improve reliability by eliminating time-consuming manual dispatch and aid price formation by incorporating additional resources into LMPs. Non-dispatchable generators enter the market as price takers and cannot be marginal.

The RTO said the rules also will aid the participation of storage resources, which both consume and inject energy, in the energy market.

The rules are similar to the “Do Not Exceed” dispatch rules FERC accepted in 2015 for wind and most hydro resources (ER15-1509).

Timber harvesting | *Innovative Natural Resource Solutions*

Going forward, only solar, nuclear, settlement-only and most external resources will remain non-dispatchable. Demand response resources will remain non-dispatchable until they are fully integrated into the energy market in 2018, according to ISO-NE.

The RTO says it will propose changes to make larger solar resources dispatchable once it has developed a way to accurately forecast their output, similar to its short-term wind forecast system.

In approving the rule changes, the commission rejected contentions from Eversource Energy that the changes violated the rights of qualifying facilities under the Public Utility Regulatory Policies Act.

“A QF is not obligated to participate in the ISO-NE administered energy markets and can instead choose to operate exclusively as a behind-the-meter resource on its host utility’s system and not be under ISO-NE’s direct operational control and not be subject to the proposed revisions,” the commission said.

December 12, 2016

Trump Transition Bodes Ill for Clean Power Plan

By Rich Heidorn Jr.

President-elect Donald Trump last week selected a climate change skeptic as EPA administrator, while his transition team probed the Department of Energy’s climate research and sought ways for the department to aid struggling nuclear power plants. Meanwhile, Congressional Republicans quashed hopes for a bipartisan energy bill.

trump climate change energy clean power plan — Pruitt | *ScottPruitt.com*

The big news in another whirlwind week was Trump’s selection of Oklahoma Attorney General Scott Pruitt, a leader of the 29-state legal challenge to the Clean Power Plan, as EPA administrator.

Pruitt issued a statement through the transition team vowing to save the “billions of dollars drained from our economy due to unnecessary EPA regulations.”

“I intend to run this agency in a way that fosters both responsible protection of the environment and freedom for American businesses,” he added.

In May, Pruitt coauthored an article in the National Review that said the science of global warming “is far from settled.”

The article also criticized the CPP, saying “this EPA regulation, one of the most ambitious ever proposed, will shutter coal-fired power plants, significantly increase the price of electricity for American consumers and enact by executive fiat the very same cap-and-trade system for carbon emissions that Congress has rejected.”

Oklahoma’s Energy Economy

Oklahoma would be required to cut carbon emissions from power plants by almost one-third under the CPP. About one-quarter of all jobs in the state rely directly or indirectly on the energy industry — mostly gas and oil.

In 2014, The New York Times reported that Pruitt had sent letters to EPA and other federal officials — on state government stationary and signed by him — that had been authored by oil and gas companies.

trump epa clean power plan — EPA Headquarters | © *RTO Insider*

Environmental groups were aghast, but unsurprised, at Trump’s choice. The Sierra Club complained Pruitt’s appointment was tantamount to “putting an arsonist in charge of fighting fires.”

Democrats vowed to oppose Pruitt’s confirmation, saying they hope to win support from some Republican senators. “This is going to be a litmus test for every member of the Senate who claims not to be a denier,” Sen. Brian Schatz (D-Hawaii) said on a call with reporters.

But Pruitt’s nomination will go through the Senate Environment and Public Works Committee, headed by fellow Oklahoman Jim Inhofe, who famously brought a snowball onto the Senate floor in 2015 to illustrate his skepticism of climate change.

‘Studying’ Paris Agreement

Trump, who has called climate change a “hoax” and vowed during the campaign to abandon the U.S.’s commitments under the Paris Agreement, said last month that he had an “open mind” on the subject. (See Trump Sends Conflicting Signals on Climate Change.)

In an interview with Fox News broadcast Sunday, Trump said he was still “studying” the agreement, saying he didn’t want it “to put us at a competitive disadvantage with other countries.”

“As you know, there are different times and different time limits on that agreement,” he said. “I don’t want that to give China or other countries signing agreements and advantage over us.”

If the CPP survives the court challenge, it will not be a simple matter to undo. “Mr. Pruitt and the incoming Trump administration cannot simply rely on their preferences or on baseless claims about science and markets,” Georgetown University Law professor William W. Buzbee wrote last week. “Decades of law, much of it created by conservatives’ judicial heroes, requires presidents and agencies to abide by the rule of law and justify regulatory reversals. They have to take a hard look at science and other underlying facts.”

Interior, DOE Candidates Emerge

Pruitt was just one of the energy-related appointments in the news last week.

trump energy epa clean power plan — McMorris Rogers | *Congress.gov*

Numerous reports said Rep. Cathy McMorris Rodgers (R-Wash.) will be named head of the Interior Department. Trump has called for opening more federal lands and waters to oil and gas development.

News reports that Trump has chosen ExxonMobil CEO Rex Tillerson as secretary of state were dominated by questions over the executive’s ties to Russia. But the company also has figured prominently in the climate debate.

New York Attorney General Eric Schniederman is leading an investigation into the company for allegedly making misleading statements on the subject in the past. After Tillerson took over as chief executive in 2006, however, the company acknowledged the science behind climate change and expressed its support for a carbon tax and the Paris Agreement.

Former Texas Gov. Rick Perry is Trump’s pick for energy secretary, CBS reported late Monday. The Department of Energy was one of three federal agencies Perry vowed to abolish — and the one he was unable to name during a debate in the 2012 presidential race.

Bloomberg reported that other finalists included Democratic Sens. Heidi Heitkamp of North Dakota and Joe Manchin of West Virginia and Ray Washburne, CEO of Charter Holdings, a Dallas-based investment company with interests in real estate and restaurants.

DOE ‘Witch Hunt’?

Meanwhile, Trump’s transition team caused a stir by submitting to the Department of Energy a long questionnaire requesting the names of all employees involved in climate research.

The questionnaire “suggests the Trump administration plans a witch hunt for civil servants who’ve simply been doing their jobs,” the watchdog group Public Citizen said in a statement.

Other questions asked about the social cost of carbon and computer modeling scientists use to forecast future climate changes.

“My guess is that they’re trying to undermine the credibility of the science that DOE has produced, particularly in the field of climate science,” Stanford climate researcher Rob Jackson told The Washington Post.

Bloomberg News reported that the transition team also asked how the department can “support existing reactors to continue operating” and what it can do “to help prevent premature closure[s].” The team also asked about obstacles to resuming work on Yucca Mountain in Nevada, the proposed site for disposing spent nuclear fuel until the plan was nixed early in President Obama’s first term. (See related story, Entergy, Consumers Announce Closure of Palisades Nuke.)

Energy Bill Appears Dead

Last week also ended hopes for enacting the first comprehensive energy bill in almost a decade.

A spokesman for House Speaker Paul Ryan (R-Wis.) said Wednesday that time had run out in the lame duck session to reach a compromise between House and Senate versions of the legislation. (See House, Senate Conferees Begin Work to Narrow Differences on Energy Bill.)

Bloomberg said Sen. Lisa Murkowski (R-Alaska), chairman of the Senate Energy and Natural Resources Committee, and ranking member Maria Cantwell (D-Wash.) had reached an agreement with Rep. Rob Bishop (R-Utah) on a package, but House leaders had refused to move it.

“It’s just very frustrating to see Congress again fail to act on energy efficiency policies that have so much bipartisan political, business and public support and that would help so many people and businesses save money on their energy bills,” Alliance to Save Energy President Kateri Callahan said in a statement. “Caught up — this round — in the failure of conferees to produce a comprehensive energy bill, the very important, practical and bipartisan provisions of the Portman-Shaheen Energy Security and Industrial Competitiveness Act (ESICA) are left in the dust bin of yet another Congress.”

December 12, 2016

CAISO to Rely on New Emergency Measure to Ease Path 26 Transfers

By Robert Mullin

CAISO said it will use a recently approved West-wide system reliability measure to ensure that its grid operators have the ability to send power into Southern California when Aliso Canyon gas pipeline restrictions constrain gas-fired generation output.

Peak Reliability — the West’s reliability coordinator — endorsed the new system operating limit (SOL) methodology, which provides Western Electricity Coordinating Council transmission operators the qualified ability to relax seasonal performance standards for “credible multiple contingencies” on a network under emergency conditions.

“That actually ends up meaning that, if we can technically justify it, we don’t have to hold to planning criteria in real-time operations,” Danny Johnson, CAISO senior operations engineer, said during a Dec. 7 market performance and planning forum.

The ISO will employ the new methodology to replace its previous authority to reserve transmission capacity on Path 26 — the major transmission link between the Southern California Edison and Pacific Gas and Electric service areas.

That authority was included in a raft of Aliso Canyon-related market provisions approved by FERC last spring, but the ISO asked to retire the authority this fall when it filed to extend most of the measures for a year beyond their original Nov. 30 sunset date. (See FERC OKs One-Year Extension for CAISO’s Alison Canyon Gas Rules.)

aliso canyon path 26 transfers caiso — Restrictions related to the shutdown of the Aliso Canyon gas storage facility have prompted CAISO to employ a new methodology to ease energy transfers into Southern California under emergency conditions. | *California Department of Emergency Services*

“Instead, we can use the Peak SOL methodology to increase transfer capability that the previous internal reservations gave us,” Johnson said.

Johnson explained that WECC path limits are established using pre-contingency power flow studies performed at the time that a path is identified or after an element along the path has undergone a significant change. Transmission paths are not re-evaluated on a regular basis, so SOLs do not account for minor changes in area load profiles or network topologies attributed to outages. The limits also fail to factor in real-time voltage conditions.

“We plan on using our real-time contingency analysis [RTCA] tool to monitor the actual elements that the path is trying to protect,” Johnson said. “This is more accurate because it’s not a pre-contingency proxy limit — it’s actual real-time data, built on voltage data. We’re able to reflect all of the neighboring topology changes either due to system changes or outages, which are constantly occurring,” allowing the ISO to observe a more accurate SOL in real time.

The RTCA tool also enables CAISO to incorporate the use of remedial action schemes — plans designed to automatically initiate corrective actions after detection of certain system conditions — to relieve congestion by strategically shedding load or generation to avoid overloading a line.

The ISO has determined that remedial action schemes (RAS) have “armed” an increasing amount of targeted SoCalEd load for shedding since the SOL for Path 26 was established in 2006.

“So in real time, if we assume that there’s additional load that will be dropped, that’s additional congestion relief that the RAS will provide,” Johnson said.

Use of the RTCA reduces the potential for Path 26 to hit its thermal limit, providing the ISO more latitude in exceeding the line’s 4,000-MW rating when Southern California gas restrictions hobble the region’s generators. The ISO estimates it could squeeze out a “few hundred” extra megawatts of transfer capability on the line under certain real-time conditions.

“We plan to use this only as a last-gasp emergency measure,” Johnson said. “By the time we use this, we will have exhausted all internal generation resources within Southern California, all demand response.”

Because the methodology requires use of real-time data, it cannot be incorporated into CAISO’s day-ahead market, which — along with the real-time market — will continue operating with the path’s current ratings from the ISO transmission register.

While CAISO has set no precise time limit for employing the measure to relieve a constraint, it expects any such event to be of limited duration.

“We want to drive back to the normal limit as soon as possible, so we wouldn’t presumably increase the market limit,” said Mark Rothleder, CAISO vice president for market quality and renewable integration. “So we would bind around that market limit trying to get back, but it would be the cushion to prevent having to drop load.”

Brian Theaker, director of market affairs at NRG Energy, asked whether the ISO intended to limit using the measure for just Path 26.

“At this time, that is where we see this being used,” Johnson responded. “I think that we would be open to using it on any WECC path that we would need to if real-time conditions dictate.”

Noting that CAISO said it could not notify market participants before or during a Path 26 event, Carrie Bentley of Resero Consulting asked what would be the most “preferable way for [ISO operations] to make this more transparent.”

Rothleder said he would have to take that question back to CAISO management.

“I think we may be able to say that these events are fairly rare,” Rothleder said. “If the event happens, we’ll give some notification after the fact, but I don’t want operators having to think, ‘Well I have to get this information out,’ while they’re trying to struggle through the event.”

December 12, 2016

Transmission-Distribution ‘Seams’ May Be Next Hurdle for Planners

By Rory D. Sweeney

WILMINGTON, Del. — The increasing complexity of distribution systems is creating a new “seam” for grid operators, representatives from an industry planning collaborative, the U.S. Department of Energy and Johns Hopkins University said at PJM’s General Session last week on the evolution of system planning.

The growth of distributed energy resources is changing the one-way flow of distribution systems, complicating their relationship with the transmission grid, speakers said.

transmission-distribution seams pjm — Whiteley | © *RTO Insider*

“Transmission and distribution planning and operations are separate, so the problem becomes understanding the changes on one and how they impact the other,” said David Whiteley of the Eastern Interconnection Planning Collaborative. “In the vertically integrated world, I think the two pieces of planning would merge. … We talk about seams issues with neighbors on transmission. You’re going to have seams issues with the distribution.”

Stan Hadley of the Oak Ridge National Laboratory extended the analysis to the natural gas pipeline network. He noted a study of natural gas sufficiency in New England during the winter that found that the constraint was the lack of pipelines across New York.

“They’ve been pushing away on building those pipelines,” he said.

Whiteley said infrastructure planning has become increasingly complex.

“It’s not a predictable load shape anymore. Generation planning is at arm’s length from transmission planning in many regions of the country, so how can you plan the transmission system if you don’t know where the generation’s going to be?” he said. “You don’t know if a line can be built or what year it will possibly come into service. That complicates the prediction of what the future looks like. All of this takes additional time; it takes additional resources.”

Researchers must understand not only the electric grid but also the natural gas distribution system, physical security issues, political dynamics and an ever-growing list of NERC reliability standards, Whiteley said.

“I used to work at NERC, but even I was shocked at the volume — over 100 standards; 3,000 pages of material on the NERC standards,” he said. “Everything is in the context of the search for what I call the ‘Holy Grail of Planning’: co-optimization of everything.”

Whiteley said incorporating complexity increases understanding of the system but makes planning far more time consuming. He highlighted an EIPC study that defined eight resource-planning futures and analyzed three of them 20 years into the future. The single study took two and a half years, he said.

Having to choose between potential scenarios to study is a dilemma that Johns Hopkins professor Ben Hobbs is attempting to eliminate with his research into “stochastic multistage integrated network expansion.”

“The key thing is we’re making decisions today not knowing which paths we’re going to go down,” he said. “What to build now; what to build later; what’s the value of flexibility. … You’re doing this all at once in one large, linear program.”

While Hobbs’ modeling can take days to run depending on the complexity, it’s already shown success in producing otherwise unseen and money-saving guidance. A study for the Western Electricity Coordinating Council uncovered several insights likely to improve the value of transmission planning over a 40-year outlook by approximately $3.5 billion, he said.

“Under proactive planning, you get more transmission and definitely different siting” for generation, Hobbs said.

Another challenge is integrating individual reports into a cohesive overview, Hadley said. Through the Grid Modernization Laboratory Consortium, he is working on standardizing a “common language” for studies so that results can be compared.

“The idea is being able to show your results and other people can see where you came from,” he said. With current procedures, “you sometimes don’t know what the underlying assumptions were.”

December 12, 2016

MISO Board Approves MTEP 16’s $2.7B in Tx Projects

By Amanda Durish Cook

CARMEL, Ind. — MISO’s 2016 Transmission Expansion Plan, with 383 projects totaling $2.7 billion, won the Board of Directors’ unanimous approval Dec. 7.

The 13th annual transmission package shed 11 projects and $100 million in investment from the preliminary plan that was unveiled in September. (See MTEP 16 Proposes 394 Projects at $2.8 Billion.)

The approved plan calls for less spending on fewer projects than MTEP 15’s $2.75 billion on 345 projects. It brings transmission investment in the footprint to 1,246 projects totaling about $15.6 billion since 2003.

miso board mtep — Curran | © *RTO Insider*

MISO Vice President of System Planning and Seams Coordination Jennifer Curran said some stakeholders wrote a letter encouraging the RTO to open the plan’s lone market efficiency project — the $80.9 million Huntley-Wilmarth 345-kV line in Minnesota — to competitive bidding.

The project, however, is covered by the state’s right-of-first-refusal statute. Curran said MISO counsel conducted another legal review of the Huntley-Wilmarth project and concluded that the RTO must respect state and local laws. “It would be inconsistent with our Tariff, and our Tariff respects that right-of-first-refusal law,” she said.

MISO Director Michael Evans asked if there was anything else the RTO could research about the legality of opening Huntley-Wilmarth to competitive bidding, but Vice President of Transmission and Technology Clair Moeller said, “Based on our Tariff and state law, we’re right where we need to be.”

“MTEP is a remarkable document. Planning from the Gulf of Mexico to the Hudson Bay is a dream … and it’s being done very well,” Evans concluded. “The direction of change remains the same, but the pace of change is up in the air.”

Evolving Fleet Influencing MTEP Futures Regardless of Presidency

Curran said MTEP 17’s futures, which on average predict a one-third coal, one-third gas and one-third renewables mix by 2030, are still relevant, despite the election of Donald Trump, who has vowed to “save” the coal industry. (See related story, Trump Transition Bodes Ill for Clean Power Plan.)

During the Dec. 6 System Planning Committee of the Board of Directors meeting, Curran said she expects three unchanged futures to be finalized in 2017. (See “MTEP 17 Futures Finalized,” MISO Planning Advisory Committee Briefs.)

“This is a more interesting topic since the election,” Curran said. “We’ve gotten a lot of calls since the election asking what has changed. In our view, we see our generation fleet continuing to evolve.”

Curran said the real uncertainty facing MISO is how fast those changes will take place, but she said regardless of federal energy policy and the presidency, fleet evolution will continue.

“We see and hear our members and state’s intentions to move forward with a lower-carbon fleet,” Curran said, citing carbon reduction measures in states’ fixed resource adequacy plans, continued low gas prices and the number of renewables in MISO’s interconnection queue, where wind comprised 69% of total megawatts reaching the queue’s definitive planning phase in 2016.

Curran said in the next 15 years, 8 GW of coal could retire based on the average 65-year coal unit lifespan and 16 GW of natural gas and oil generators could retire assuming their average 55-year lifespan. She said MISO plans to initiate a study in 2017 to examine the reliability impacts of aged-based generation retirements.

Moeller said MISO’s aim is simple: political-free planning.

“The most important criteria is that we’re working on the right thing. I think we’re pointed towards that,” Evans said.

December 12, 2016

IMM Report Highlights Outages, Wind Over-Forecasting

By Amanda Durish Cook

CARMEL, Ind. — High generation outage rates in MISO South and suspicions of deliberate over-forecasting by wind operators highlighted the concerns of MISO’s Independent Market Monitor in the fall.

Monitor David Patton presented the draft of his fall report at the Dec. 6 meeting of the Markets Committee of the Board of Directors, saying that MISO’s markets performed “competitively and reliably” with “infrequent” market mitigation.

miso imm outage rates — MISO’s Markets Committee of the Board of Directors listens to IMM David Patton’s conference report. | © *RTO Insider*

MISO’s fall load peaked at 115 GW on Sept. 6. Patton said a 15% increase in real-time energy prices from last fall could be traced to a 13% increase in natural gas prices over the same period last year. He said a 4% year-over-year increase in wind output — which set a new record at 13.3 GW of production on Nov. 28 — led to higher congestion and price volatility. Combined with high levels of generator outages, there was higher congestion in the day-ahead and real-time markets relative to last year, Patton said.

Day-ahead congestion increased by 18% over 2015 to $202.7 million and real-time congestion increased by 9% to $345.1 million. “Prices, particularly in the three southern hubs in October jumped up … due to some pretty significant congestion,” Patton said.

Outages Approach 40%

Patton said generation outages in MISO South were of particular concern, increasing from an average of 18.2% in fall 2015 to 31.6% in fall 2016. As October approached, Patton said, MISO South outage rates almost reached 40%. “This is an unusually large quantity to have out,” he said.

Unseasonably warm weather produced unusually high loads and led to a maximum generation alert Oct. 4-5. Patton said the tight conditions were due in part to the high outage rates in MISO South.

“It appears that if we could do anything better as a market, it’s managing the scheduling of the outages in MISO South,” Vice President of System Planning and Seams Coordination Jennifer Curran said.

“That’s fair,” Patton responded, adding that MISO should have more authority over generation outages.

Vice President of System Operations Todd Ramey said high temperatures and the high number of scheduled outages, combined with forced outages and derates, contributed to the reliability concerns.

“As an industry we tend to focus on the winter, but it’s true that the most challenging situations are the shoulder periods where outages are high,” Ramey said. He also said MISO is taking “a hard look” at adjusting outage coordination in MISO South. Jeff Bladen, executive director of market services, said the season proved the value of the North-South transfer path, as the outages were offset by MISO North power.

Curran said the Tariff might need to be “opened up” to give MISO the authority to coordinate planned outages in advance “so you aren’t just responding to the conditions as they’re dealt, but you can influence them.”

Wind Operators’ ‘Bias’

Patton repeated concerns that wind operators were deliberately over-forecasting their supply to earn more from MISO’s day-ahead margin assurance payment. (See MISO IMM Sees Deliberate Over-Forecasting by Wind Operators.)

Board member Baljit Dail asked if Patton had a sense of the size of the overpayments.

Patton said that while he didn’t find gaming had occurred “in an obvious fashion,” he estimated MISO has paid $6 million in unjustified payments over the past year to year and a half. “The [wind operators] are not forecasting badly because they don’t have the technology; they’re forecasting badly because they have a bias,” Patton said.

Richard Doying, MISO’s executive vice president of operations and corporate services, said the RTO continues to evaluate instances of wind over-forecasting and would approach the board with findings and possible solutions later.

Director Phyllis Currie defended the RTO, saying it is looking to put people and resources in place to conduct their own wind forecasts. “Load forecasting is not an exact science,” she pointed out.

Patton agreed that MISO should not rush a solution.

On average in fall 2016, wind units predicted an average day-ahead wind supply of 4,324 MW and produced 5,141 MW in real time.

Patton also told the board that he continues to work with MISO on expanding a pilot program to create temperature-adjusted transmission ratings. “When temperatures are cooler, you can transfer a lot more power,” Patton said.

December 12, 2016

Increased Transfer Capacity Reducing EIM Congestion

By Robert Mullin

Increased transfer capacity is keeping a lid on congestion in the Western Energy Imbalance Market (EIM) and limiting participants’ ability to wield market power within their balancing authority areas, according to CAISO’s internal Market Monitor.

Gabe Murtaugh, a senior economist with the ISO’s Department of Market Monitoring, told a Dec. 7 Market Performance and Planning Forum that the increased capacity could help Arizona Public Service, NV Energy and PacifiCorp in reapplying to FERC for market-based rate authority. Citing market power concerns, FERC has limited the three companies to cost-based offers. (See CAISO Monitor Proposes Fixes for EIM Market Power Concerns.)

Puget Sound Energy — the only EIM member currently permitted to make market-based offers — has committed to the market 300 MW of bidirectional transfer capacity with the PacifiCorp-West balancing area. Those transmission links were congested during just 1% of intervals in the May-October period, Murtaugh said.

APS’ average outbound/inbound EIM transfer capability of 1,874 MW/924 MW with CAISO saw almost no congestion during the period, while the utility’s 321-MW/216-MW link with PacifiCorp-East showed congestion during 1% and 7% of intervals, respectively. Despite the proximity of their balancing areas, there is no EIM transfer capability between APS and NV Energy because of the limited availability of capacity to commit to the market.

Average transfer capacity among CAISO, NV Energy and PacifiCorp-East remained steady from May to October, and links between the areas were subject to relatively light congestion over the period. PacifiCorp-East’s outbound link into NV Energy was most congested during spring, when inland power prices are cheap.

The one exception to low congestion: transfers from PacifiCorp-West into CAISO via limited capacity available on the California-Oregon Intertie. The intertie is congested 20% of the time, in part because of the variability of transfer capacity made available to the EIM during given intervals.

Graphic illustrates the percentage of intervals for which each EIM intertie was constrained during May-October and the average volume of transfers during each congest interval. Figures for Arizona Public Service and Puget Sound Energy are for October only. | *CAISO*

“Generation in PacifiCorp-West is generally cheaper than generation that we see in the ISO and the rest of the EIM,” Murtaugh said. “And when prices are high in the ISO, [PacifiCorp-West] generation increases its output until it reaches its limit for export.”

That constraint has historically led to price separation between PacifiCorp-West and the rest of the EIM.

PacifiCorp’s new EIM link with Puget Sound Energy is alleviating that isolation in most hours. Now, when there is congestion between PacifiCorp and CAISO, the ample transfer capability between PacifiCorp-West and Puget Sound means that PacifiCorp prices are set by the marginal generation in both areas, rather than just PacifiCorp-West, Murtaugh said.

But Pacific Northwest prices will still tend to diverge from the rest of the market.

“When prices are higher in the rest of the system, we see generation about as high as it can get in PacifiCorp-West,” Murtaugh said.

That pushes on the constraint out of PacifiCorp-West, causing price discrepancies between that area — and, now, Puget Sound as well — and the remainder of the EIM.

While price divergences stemming from congestion drive concerns about market power in the EIM, the Monitor finds that congestion is occurring in “a very low percentage of intervals” — even in the five-minute market, when congestion tends to be most elevated.

“The underlying message here is there isn’t a whole lot of opportunity to exercise market power during [most] intervals,” Murtaugh said.

December 9, 2016

Entergy, Consumers Announce Closure of Palisades Nuke

By Tom Kleckner

Citing market conditions that have changed “substantially” and the availability of “more economic alternatives,” Entergy announced Thursday it intends to shut down its Palisades nuclear plant on Oct. 1, 2018.

Entergy said a power purchase agreement between the plant, located in Covert Township, Mich., and Consumers Energy would be terminated four years early in 2018. Consumers will pay Entergy $172 million for terminating the PPA. According to Entergy, the termination will also save Consumers customers $172 million in costs over four years.

The companies entered the 15-year PPA in 2007, when Entergy bought the plant from Consumers parent CMS Energy for $380 million. However, the agreement’s prices exceed market prices and escalate each year, reaching $61.50/MWh in 2022.

“We determined that a shutdown in 2018 is prudent when comparing the transaction to the business risks of continued operation,” Entergy CEO Leo Denault said in a press release.

In its most recent 10Q, Entergy said the “fair value of the Palisades plant would have been, and currently would be, significantly lower in the absence of the power purchase agreement that is scheduled to expire in 2022.” It also pointed to the drop in energy prices in MISO, in which Palisades operates.

Palisades Nuclear Power Plant | *Palisades Power*

The early termination payment “will help assure the plant’s transition from operations to decommissioning,” Entergy said. The plant will be refueled as scheduled next spring and then operate through the end of its fuel cycle.

With Palisades’ closure, Entergy will have only one nuclear generating facility in its Wholesale Commodities business, the 40- and 42-year-old Indian Point units near Manhattan. Like other plants in the portfolio, Palisades is older (1971) and smaller (811 MW) than later-generation nuclear units.

In February, Entergy estimated the plant’s fair value and related long-lived assets at $463 million, compared to a carrying value of $859 million. It said last month the wholesale business lost $13 million in the third quarter as compared to the previous year because of lower-realized wholesale prices.

In recent years, the company has shut down or announced the closure of its Vermont Yankee and Pilgrim plants in New England. And on Wednesday, FERC approved the sale of its James A. FitzPatrick plant in New York to Exelon. (See related story, FERC Approves FitzPatrick Sale to Exelon.)

“Entergy’s strategy is to manage risks by reducing our merchant power market portfolio and invest in the growth of our regulated utility business,” Entergy spokesperson Val Gent said. Entergy still owns five nuclear reactors in the South as part of its utility generating business.

Reaction

The agreement between Entergy and Consumers is subject to regulatory approvals, including the Michigan Public Service Commission, but the announcement quickly drew pushback from elected officials in the state.

State Rep. Aric Nesbitt (R), who chairs the House Committee on Energy Policy and whose southwestern Michigan district is home to Palisades, called Entergy’s announcement a “punch in the stomach” and said it “puts Michigan’s energy future at greater risk.”

“I call on Entergy to reconsider its decision to prematurely close Palisades and work with the state to find a solution to keep Palisades open and producing reliable, emission-free energy,” he said in a press release. “This announcement further threatens Michigan electric reliability after 2018. This is not just a bad decision for our local families, but it is also the wrong decision for Michigan’s energy future. I demand that Entergy reconsider this poorly made decision.”

Gov. Rick Snyder was more subdued. In a statement issued by his office, Snyder said, “I’m certain the Michigan Public Service Commission will look at this very closely and examine the implications for the reliability and affordability of electricity in Michigan, as well as protection of the environment.

“No matter what the eventual decision is, it is important that we do everything to help the region adapt to a potential future without Palisades,” he said.

For its part, MISO will follow its normal confidential process for generator retirements to determine whether Palisades’ absence will jeopardize reliability. The RTO’s Tariff requires companies to notify it at least 26 weeks before the proposed retirement, which then sets the clock on a study evaluating any reliability issues.

Entergy said it expects to recognize an approximately $390 million non-cash impairment charge ($252 million after taxes) in the fourth quarter and another $55 million in relevant charges through the end of 2018.

The corporation’s stock price, which closed Wednesday at $70.44/share, opened the day at $69.88/share before erasing the early drop. Entergy’s share price climbed to $70.55/share by early afternoon.

December 8, 2016

FERC Approves FitzPatrick Sale to Exelon

By William Opalka

FERC on Wednesday approved Exelon’s acquisition of the troubled James A. FitzPatrick nuclear plant in New York, rejecting a protest that its review should have included the impact of a state-mandated ratepayer subsidy (EC16-169).

Plant owner Entergy told New York officials that without the $110 million sale, the 882-MW plant would close at the end of January. New York regulators approved the transaction last month. (See NY Regulators Approve FitzPatrick Sale.)

But consumer advocate Public Citizen, in a protest filed with FERC in October, complained that the companies omitted information on the zero-emission credit program New York had passed to prop up upstate nuclear plants, which the group argued made the application incomplete. It also said the subsidy itself distorts the New York market and violates the NYISO Tariff. (See Public Citizen Challenges NY Nuclear Subsidy, FitzPatrick Sale.)

entergy, fitzpatrick, exelon, public citizen, nuclear power — FitzPatrick Nuclear Plant | *Entergy*

Entergy and Exelon said such a review was beyond the scope of FERC evaluation of the sale, which should be limited to whether it gave the buyer excess market power and if the sale was in the public interest.

The commission agreed.

“We will dismiss Public Citizen’s protest of the proposed transaction because the issues Public Citizen raises concern the ZEC program rather than the effects of the proposed transaction on competition, rates, regulation or cross-subsidization,” the commission wrote. “Public Citizen … focuses on the potential effects of the ZEC program on the NYISO market rather than the effects of the proposed transaction.”

FERC said such questions could be addressed in another proceeding, which Public Citizen appears prepared to do.

Tyson Slocum, director of Public Citizen’s energy program, on Thursday said the groups would first ask for a rehearing of this week’s order and later challenge the ZECs under a Section 206 proceeding.

Slocum said he found FERC’s rationale “very strange” for limiting the scope of order.

“It’s very clear that the transaction would not have occurred without the ZEC program,” he said. “But there was no review of how [ZECs] will affect market power, pricing and how it gives [the plants] a competitive advantage.

“FERC is acting as if these changes to the market don’t exist,” Slocum added.

Critics of the ZEC program say it will cost ratepayers $7.6 billion over its 12-year life. New York says the program helps combat climate change and its costs are more accurately measured by the federal “social cost of carbon” calculation.

After the Nuclear Regulatory Commission gives its approval and the deal closes, Exelon will be the sole owner of the upstate nuclear fleet, which consists of three plants that make up 5.9% of the state’s generation.